Initial production of petroleum from subsurface reservoirs, referred to as primary production, frequently is accompanied by produced water (brine). The produced water must be separated from the oil and discarded or otherwise disposed of. Frequently the separated produced water is pressure injected into the same or another oil reservoir with the intention of increasing oil recovery from the reservoir. Such a reinjection process is referred to as a secondary recovery process with subsequent treatment processes referred to as tertiary processes. During primary oil recovery, the oil/water ratio in produced fluids is typically one part water to three parts of oil. During secondary and tertiary oil recovery, the water content in the produced fluids frequently increases to an oil/water ratio of fifty or more parts water to one part oil until continued production is no longer economically viable.
For water to be satisfactorily injected into a reservoir, whether for purposes of disposal or improved oil recovery, the water should be sufficiently "clean" to enter the subsurface formation (a porous medium) without causing formation plugging. If the subsurface formation becomes plugged, progressively higher water injection pressures may be required to maintain a desired injection volume. At some point, the fracture pressure of the formation can be reached resulting in possible fracturing of the formation. If fracturing occurs the resulting "thief zone" in the fractured formation can establish low resistance paths through the formation that can steal most of the injection water. The result is a poor injection profile and the bypassing of formation oil which might have been captured in secondary or tertiary recovery. Furthermore, subsequent plugging of a "thief zone" is costly, difficult and often impossible.
Deposition of solids in the porous subsurface formation and on the face of the injection wellbore from injection waters may result in the need for an injection well "workover" or a stimulation of some kind within the formation. Processes such as a mechanical scraping and bailing, acidizing, solvent washing and various combination treatments can be used but such processes are very expensive. In some cases an expensive side-track well may be drilled. In other instances, the original well can only be adandoned. A substantial economic incentive exists, therefore, to provide clean (solids-free) water for injection into the subsurface formation in a water injection process to avoid formation damage.
Water filtration equipment is affected by the cleanliness of the water separated from the produced fluids. Poor water clarity, whether due to inadequate filtration or the post-precipitation of solids, also causes severe problems in other surface facilities. In the surface facilities of oil field equipment, inorganic deposits (scale), coated by gelatinous solids, frequently called organic slime, often adhere to the internal surfaces of filters, pumps, valves, storage tanks, and distribution pipelines. When these surface facilities become clogged the equipment must be shut down and cleaned. This introduces costly downtime and maintenance expenses. "Pigging" (mechanical internal reaming) of pipelines is sometimes required to maintain pipeline capacity.
Water quality is also affected by system upsets which occur with surges of oil flowing into the surface water treating equipment, seemingly at random periods, requiring frequent change of filter media and/or frequent filter backwashing cycles.
It is also known that oil well scale in the form of carbonate scale depositions is die to the loss of carbon dioxide from bicarbonate bearing waters. The petroleum industry has struggled with carbonate scale deposition and has generally attacked the problem by the addition of scale inhibiting chemicals, acidizing techniques, and various types of filters in series. None of these approaches have been directed toward the source of the problem; i.e., the loss of carbon dioxide from bicarbonate bearing waters.
Several recent changes have introduced new considerations to oil production and oil field water treatment in which carbonatebicarbonate chemistry is involved. These changes include:
1. Production of Heavy Oil
Because lighter more easily refined crude oils are being depleted throughout the world, production of heavy, viscous crude oils is increasing rapidly. Heavy crude oils make the separation of oil from water more difficult, due in part to surface active components (organic acids) prevalent in these oils. When produced water loses pressure in surface facilities there is an increase in pH (higher alkalinity) resulting from loss of carbon dioxide. Carbonate scale begins to form increasing the tendency to drag organic matter into the water. This organic matter frequently is adsorbed onto inorganic solids which have precipitated from the water. The result is a composite gelatinous slime which is extremely difficult to remove by filtration.
2. Stringent Regulations For Waste Water Disposal
These regulations combined with the above change have required the extensive use of flotation cells to remove more oil from the produced water.
3. Methane (Natural Gas) As Frothing Gas in Flotation Cells
Since methane is usually readily available at a producing well, it is commonly used as a frothing gas in flotation cells in oil producing operations to remove additional suspended solids and traces of oil. Methane, however, causes a stripping or loss of dissolved carbon dioxide. This loss of carbon dioxide shifts the chemical equilibrium toward higher pH level and toward the formation of carbonates. Therefore the use of methane gas in water treatment process can be counterproductive to improving water clarity.
4. Large Central Treating Facilities
Centralized facilities require produced fluids to be pipelined over considerable distances, sometimes many miles. At the centralized facility the oil and water are separated, the water is clarified and finally the clarified water is returned to injection wells. The longer time, increased distances and greater storage (tankage) requirements allow more carbon dioxide to escape from the water aggravating the problem of solids precipation. Additionally, more and greater pressure changes frequently occur in large central facilities than in smaller field units. Such changes in system pressure are also conducive to the escape of carbon dioxide from the water being treated.